Africa Oil Corp.
TSX : AOI
OMX : AOI

Africa Oil Corp.

September 16, 2014 00:00 ET

Africa Oil Announces Significant Increase in Resource Estimates of Kenya Oil Fields and Conference Call

VANCOUVER, BRITISH COLUMBIA--(Marketwired - Sept. 16, 2014) - Africa Oil Corp. (TSX:AOI)(OMX:AOI) ("Africa Oil", "AOC" or the "Company") is pleased to announce that an independent assessment of the Company's Contingent Resources in the South Lokichar Basin located in Blocks 10BB and 13T in Kenya has been completed by Gaffney, Cline & Associates ("Gaffney Cline" or "GCA").

Total 2C gross contingent resources increased 67% to 616 million barrels of oil and total 3C gross contingent resources increased 52% to 1.29 billion barrels of oil in the oil fields discovered to date in the South Lokichar basin. The Prospective Resource estimates outside of the field areas in the South Lokichar Basin have not been updated and it is planned to do a comprehensive update of all resources on all properties at year end.

Given the number of discoveries in the South Lokichar Basin, the following two tables have been prepared for the convenience of readers by Africa Oil. Readers should refer to the tables attached to this News Release, which have been prepared by GCA, detailing the low (1C), best (2C) and high (3C) Contingent Resources estimates in greater detail.

Summary of South Lokichar Basin 2C Oil Contingent Resources as of July 31, 2014
Field GROSS 2C
Estimate
Millions of barrels
("mmbo")
AOC Working
Interest
(%)
NET 2C
Estimate
(mmbo)
Ngamia 340 50% 170
Ekales 20 50% 10
Twiga 62 50% 31
Agete 57 50% 28
Etuko 16 50% 8
Amosing 118 50% 59
Ewoi 3 50% 2
TOTAL 616 50% 308
Notes:
1. "Gross Contingent Resources" are 100% of the volumes estimated to be recoverable from the field in the event that it is developed.
2. Net Contingent Resources in this table are AOC's Working Interest fraction of the Gross Field Contingent Resources; they do not represent AOC's actual Net Entitlement under the terms of the PSC that governs the asset, which would be lower.
3. The volumes reported here are "unrisked" in the sense that no adjustment has been made for the risk that the field may not be developed in the form envisaged or may not be developed at all (i.e. no "Chance of Development" factor has been applied).
Summary of South Lokichar Basin 3C Oil Contingent Resources as of July 31, 2014
Field GROSS 3C
Estimate
(mmbo)
AOC Working
Interest
(%)
NET 3C
Estimate
(mmbo)
Ngamia 660 50% 330
Ekales 44 50% 22
Twiga 142 50% 71
Agete 163 50% 81
Etuko 42 50% 21
Amosing 231 50% 115
Ewoi 9 50% 5
TOTAL 1291 50% 645
Notes:
1. Gross Contingent Resources are 100% of the volumes estimated to be recoverable from the field in the event that it is developed.
2. Net Contingent Resources in this table are AOC's Working Interest fraction of the Gross Field Contingent Resources; they do not represent AOC's actual Net Entitlement under the terms of the PSC that governs the asset, which would be lower.
3. The volumes reported here are "unrisked" in the sense that no adjustment has been made for the risk that the field may not be developed in the form envisaged or may not be developed at all (i.e. no "Chance of Development" factor has been applied).

The independent assessment was carried out in accordance with the standards established by the Canadian Securities Administrators in National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. The effective date of the report is July 31, 2014.

In addition, the Company is pleased to announce that two key exploration wells have commenced drilling, the Kodos-1 well which is a basin opening well in the Central Kerio Basin and the Ekosowan-1 well, which is a large prospect on the "string of pearls" trend on the western basin bounding fault in the South Lokichar Basin directly south of the Amosing and Ngamia significant discoveries. These wells are expected to be completed by year end.

Keith Hill, Africa Oil's President and Chief Executive Officer, commented: "Gaffney Cline's independent assessment confirms a significant increase in Contingent Resources for the South Lokichar Basin in Northern Kenya. Based on the drilling and testing program over the past year our best estimate is now that the Company's discoveries in the South Lokichar Basin contain gross Contingent Resources of 616 million barrels of oil (2C estimate), an increase of 67% on previous estimates, and may contain as much as 1291 million barrels of gross oil Contingent Resources (3C estimate), an increase of 52%. This level of resources exceeds the threshold for development and we are targeting development sanction at the end of 2015/early 2016. We continue to aggressively explore and appraise the basin with three rigs operating and are currently acquiring a large 3D seismic survey in the west and north of the basin. The key factors to address to increase these resources over the next year will be related to recovery factors and reservoir connectivity and the early appraisal results at Ngamia and Amosing provide encouragement on the lateral continuity of the Auwerwer sands. The upcoming extended well tests at Ngamia and Amosing and the ongoing appraisal and core analysis programs will provide additional data to support this understanding. We also have an exciting exploration portfolio on trend with the South Lokichar Basin and will have drilled six new basins by the end of 2015. We are confident that our early successes will be repeated in at least one additional new basin."

Africa Oil's holdings in the South Lokichar Basin comprise non-operated 50% working interests in Blocks 10BB and 13T in Kenya. The South Lokichar Basin contains eight hydrocarbon discoveries in various stages of appraisal and numerous prospects and leads, that have proven and productive analogs. Since the effective date (July 31, 2013) of Gaffney Cline's previous evaluation of the contingent and prospective resources for the South Lokichar Basin, highlights of the Company's exploration and appraisal activities for this basin include:

  • Drilling and production testing the Ekales-1 well in Block 13T resulting in an additional oil discovery and demonstrating high quality Auwerwer sands containing light waxy sweet crude.
  • Drilling the Agete-1 and 2 wells and production testing Agete-1 in Block 13T resulting in an additional oil discovery with high quality Auwerwer sands containing light waxy sweet crude.
  • Drilling the Amosing-1, 2 and 2A wells in Block 10BB resulting in an additional oil discovery in high quality Auwerwer sands with further reservoirs developed in the Lokhone formation. The Amosing-2 and 2A appraisal wells suggest reservoir and pressure continuity between the wells which will be determined by the upcoming extended well test.
  • Drilling and production testing the Ewoi-1 well in Block 10BB resulting in an additional oil discovery in the lower quality Lokhone sandstones developed on the eastern flank of the basin.
  • Production testing the Etuko-1 discovery in Block 10BB further demonstrated the production potential of sands within the Lokhone shale source rock. Etuko-2A was drilled to test oil shows seen while drilling the Auwerwer reservoir at Etuko-1, the results of the well are considered inconclusive and analysis is underway to consider further options to evaluate this reservoir.
  • Drilling the Emong-1 well in Block 13T which encountered oil and gas shows in poorly developed reservoirs at the Auwerwer target interval. It is believed that the reservoir was poorly developed due to its proximity to the basin bounding fault and its location within what appears to be a local isolated slumped fault margin.
  • Drilling the Ekunyuk-1 well in Block 10BB on the eastern flank play which encountered a small zone of non-commercial oil pay within thick good quality Lokhone sands. The quality of Lokhone sands indicates that there is further exploration potential in this area of the basin.
  • Drilling the Twiga-2 appraisal wells in Block 13T located near the basin bounding fault encountered relatively thin net oil pay within an alluvial fan facies, with limited reservoir quality. The Twiga-2A sidetrack was drilled to the northeast away from the fault and encountered similar high quality Auwerwer formations to the Twiga-1 discovery. Production testing of Twiga-2A is ongoing.
  • Drilling the Ngamia-2 appraisal well in Block 10BB confirmed the thickness and lateral extent of the Auwerwer sands and identified a new fault trap, north of the main Ngamia accumulation. Drilling the Ngamia-3 appraisal well in Block 10BB further confirmed the thickness and lateral extent of the Auwerwer sands over the Ngamia structure and also extended the known oil column significantly downdip from the Ngamia-1A discovery well.
  • Drilling the Etom-1 well in Block 13T resulted in an additional oil discovery within high quality Auwerwer sands along the western basin bounding fault play. The well results were announced after the effective date for the Gaffney Cline resource assessment and are therefore still carried in prospective resources.
  • To date ten exploration wells have been drilled in the basin resulting in eight oil discoveries, an 80% success rate.
  • Acquisition of a 704 square kilometer 3D seismic survey is approximately 90% complete over the discoveries and prospects along the western basin bounding fault and fast track processed results over the Ekosowan prospect and Amosing discovery were utilized in this updated resource assessment. In addition, a further 100 kilometers of 2D seismic was acquired in the basin.
  • Acquisition of 890 meters of whole core in wells at Agete, Amosing Ekales, Etuko, Ngamia and Twiga to aid in reservoir understanding.
  • All production tests indicate similar quality light waxy sweet crudes.

The Company continues to aggressively explore and appraise the South Lokichar Basin. Two drilling rigs and a completion/test rig are currently operating in the basin and are planned to continue through 2015. The Ngamia-4 appraisal well and the Ekosowan-1 exploration well are currently drilling and production testing is ongoing at Twiga-2A.

Commitment has been made to expand the 3D seismic survey to cover an additional 247 square kilometers over the Etom area and the full survey is expected to be complete by around end first quarter 2015. Consideration is also been given to expanding the survey over the eastern flank play. It is expected that the results of the 3D seismic survey will lead to better subsurface understanding and identify additional prospectivity. Due to the delays in acquiring the 3D seismic survey the Government has recently approved a one year extension to the PSC exploration term for both blocks 10BB and 13T, which means the final exploration periods will expire in July 2017 and September 2017, respectively.

The anchor for a development of the South Lokichar Basin will be the series of high quality Auwerwer reservoir discoveries made along the western basin bounding fault at Amosing, Ngamia, Ekales, Twiga and Agete. The appraisal program is focused on increasing the subsurface certainty through multiple appraisal wells, extended well tests at Amosing and Ngamia and special core analysis. The wide distribution between 1C, 2C and 3C contingent resources is in part driven by the assumed recovery factor range for the Auwerwer reservoir of P90 - 16%, P50 - 26% and P10 - 36% which is a function of uncertainty over reservoir distribution and connectivity. The ongoing appraisal program is aimed at both narrowing uncertainty around contingent resources and confirming the Company's expectation of a recovery factor at the upper end of the current range.

The South Lokichar Basin exceeds threshold oil volumes for undertaking development studies and development planning is being fast tracked. It is anticipated that a Field Development Plan will be submitted to Government in the second half of 2015 and project sanction, including an export pipeline, is being targeted at the end of 2015/early 2016. This will be the catalyst for booking reserves for the basin.

Please refer to the tables below detailing the Company's Contingent Resources by discovery as provided by Gaffney Cline & Associates, effective July 31, 2014.

Conference Call

A conference call will held to discuss the resource update on September 16, 2014 at 11:00 ET, 4:00 p.m. UK time, or 5:00 p.m. Swedish time.

Please call in 10 minutes before the conference starts and stay on the line (an operator will be available to assist you).

Call-in number for the conference call (North America): +1 416-340-2216
Call-in number for the conference call (North America Toll Free): +1 866-223-7781
Call-in number for the conference call (Europe): + 800-6578-9898

A replay of the telephone conference will be available approximately one hour after the completion of the conference call until September 23, 2014.

Replay number in North America: +1 905 694 9451
North America (Toll Free) is: +1 800 408 3053

The pass code for the replay is: 9087224

About Africa Oil Corp.

Africa Oil Corp. is a Canadian oil and gas company with assets in Kenya and Ethiopia as well as Puntland (Somalia) through its 45% equity interest in Horn Petroleum Corporation. Africa Oil's East African holdings are within a world-class exploration play fairway with a total gross land package in this prolific region in excess of 215,000 square kilometers. The East African Rift Basin system is one of the last of the great rift basins to be explored. The Company is listed on the Toronto Stock Exchange and on NASDAQ OMX-Stockholm under the symbol "AOI".

Forward Looking Statements

Certain statements made and information contained herein constitute "forward-looking information" (within the meaning of applicable Canadian securities legislation). Such statements and information (together, "forward looking statements") relate to future events or the Company's future performance, business prospects or opportunities. Forward-looking statements include, but are not limited to, statements with respect to estimates of reserves and or resources, future production levels, future capital expenditures and their allocation to exploration and development activities, future drilling and other exploration and development activities, ultimate recovery of reserves or resources and dates by which certain areas will be explored, developed or reach expected operating capacity, that are based on forecasts of future results, estimates of amounts not yet determinable and assumptions of management.

All statements other than statements of historical fact may be forward-looking statements. Statements concerning proven and probable reserves and resource estimates may also be deemed to constitute forward-looking statements and reflect conclusions that are based on certain assumptions that the reserves and resources can be economically exploited. Any statements that express or involve discussions with respect to predictions, expectations, beliefs, plans, projections, objectives, assumptions or future events or performance (often, but not always, using words or phrases such as "seek", "anticipate", "plan", "continue", "estimate", "expect, "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe" and similar expressions) are not statements of historical fact and may be "forward-looking statements". Forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. The Company believes that the expectations reflected in those forward-looking statements are reasonable, but no assurance can be given that these expectations will prove to be correct and such forward-looking statements should not be unduly relied upon. The Company does not intend, and does not assume any obligation, to update these forward-looking statements, except as required by applicable laws. These forward-looking statements involve risks and uncertainties relating to, among other things, changes in oil prices, results of exploration and development activities, uninsured risks, regulatory changes, defects in title, availability of materials and equipment, timeliness of government or other regulatory approvals, actual performance of facilities, availability of financing on reasonable terms, availability of third party service providers, equipment and processes relative to specifications and expectations and unanticipated environmental impacts on operations. Actual results may differ materially from those expressed or implied by such forward-looking statements.

Cautionary Statements regarding Well Test Results

Drill stem tests are commonly based on flow periods of 1 to 5 days and build up periods of 1 to 3 days. Pressure transient analysis has not been carried out on all well tests and the results should therefore be considered as preliminary. Well test results are not necessarily indicative of long-term performance or of ultimate recovery.

ON BEHALF OF THE BOARD

Keith C. Hill

President and CEO

CONTINGENT RESOURCES ESTIMATES

(EXTRACTED FROM THE GCA REPORT)

TABLE 1

SUMMARY OF GROSS OIL CONTINGENT RESOURCES

AS AT 31ST JULY, 2014

Discovery Formation 1C (MMBbl) 2C (MMBbl) 3C (MMBbl)
Ngamia Auwerwer 170.1 330.3 639.7
Upper Lokone 1.1 3.1 6.8
Lower Lokone 2.6 6.4 13.8
Ekales Auwerwer 7.4 19.7 44.4
Twiga Auwerwer 20.0 52.4 112.0
Upper Lokone 3.3 9.9 29.6
Agete Auwerwer 19.1 57.0 162.6
Etuko Upper Lokone 5.4 16.0 42.3
Amosing Auwerwer 43.0 86.3 174.6
Upper Lokone 17.8 31.3 55.9
Ewoi Upper Lokone 1.2 3.3 9.2
Notes:
1. Gross Contingent Resources are 100% of the volumes estimated to be recoverable from the field in the event that it is developed.
2. The volumes reported here are "unrisked" in the sense that no adjustment has been made for the risk that the field may not be developed in the form envisaged or may not be developed at all (i.e. no "Chance of Development" factor has been applied).
3. Oil volumes are quoted in millions of barrels (MMBbl) at stock tank conditions.

TABLE 2

SUMMARY OF AOC NET OIL CONTINGENT RESOURCES

AS AT 31ST JULY, 2014

Discovery Formation 1C (MMBbl) 2C (MMBbl) 3C (MMBbl)
Ngamia Auwerwer 85.1 165.2 319.9
Upper Lokone 0.6 1.6 3.4
Lower Lokone 1.3 3.2 6.9
Ekales Auwerwer 3.7 9.9 22.2
Twiga Auwerwer 10.0 26.2 56.0
Upper Lokone 1.7 5.0 14.8
Agete Auwerwer 9.6 28.5 81.3
Etuko Upper Lokone 2.7 8.0 21.2
Amosing Auwerwer 21.5 43.2 87.3
Upper Lokone 8.9 15.7 28.0
Ewoi Upper Lokone 0.6 1.7 4.6
Notes:
1. Net Contingent Resources in this table are AOC's Working Interest fraction of the Gross Field Contingent Resources; they do not represent AOC's actual Net Entitlement under the terms of the PSC that governs the asset, which would be lower.
2. The volumes reported here are "unrisked" in the sense that no adjustment has been made for the risk that the field may not be developed in the form envisaged or may not be developed at all (i.e. no "Chance of Development" factor has been applied).
3. Oil volumes are quoted in millions of barrels (MMBbl) at stock tank conditions.

DEFINITION OF CONTINGENT RESOURCES

Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies. Contingent Resources may include, for example, projects for which there are currently no evident viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be sub- classified based on project maturity and/or characterized by their economic status.

It must be appreciated that the Contingent Resources reported herein are unrisked in terms of economic uncertainty and commerciality.

  • Low (1C) Estimate: This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate.
  • Best (2C) Estimate: This is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate.
  • High (3C) Estimate: This is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate.

There is no certainty that it will be commercially viable to produce any portion of the Contingent Resources.

CONTINGENCIES

(EXTRACTED FROM THE GCA REPORT)

The key contingencies associated with the Lokichar Basin discoveries are as follows:

  • Further data acquisition and analysis, including updated seismic mapping and depth conversion, to better characterise the reservoir extent and reduce sub-surface uncertainties in order to mature the sub-surface development plans;
  • Definition of field development plans and infrastructure requirements; and
  • Government approval and project sanction.

Seismic Mapping and Depth Conversion

The structural closure at each discovery is constrained by multi-vintage 2D seismic data. These data are sufficient to define a structural closure at each discovery, however, there remains significant uncertainty regarding the size of the trap. The area of closure and height of closure are dependent on the depth conversion methodology used. The oil-water contacts for the discoveries are uncertain; the resource estimates consider the uncertainty between the lowest known oil and structural spill-point; however, the true hydrocarbon contacts are yet to be confirmed by well logs and tests. Additional 3D seismic, currently being acquired in the basin, will allow a more precise assessment of the volume of recoverable hydrocarbons. However, further appraisal drilling and well testing is required to reduce the uncertainty in the areal extent of the reservoir pay zones.

Reservoir Characterisation

The Auwerwer and Lokhone Formations have been penetrated by the wells, drilled by AOC and its co-venturers. However, borehole stability remains an issue, resulting in the borehole being significantly out of gauge in some parts of the reservoir section. This has made log interpretation challenging and there remains significant uncertainty with regard to the average and total thickness of the reservoir pay zones and reservoir quality (porosity, net-to-gross and hydrocarbon saturation).

Maturation of Subsurface Development Plans

Oil from the Lokichar Basin wells is a waxy crude (24% to >35% wax), with a wax appearance temperature in the region of 48°C to 84°C and a pour point of 39°C to 51°C. Taking this into consideration, the use of hot water injection for secondary recovery along with artificially-lifted production wells is proposed. In order to validate this concept and optimise development, additional data and evaluation are required including further production and inter-well interference testing, water injection trials, additional fluid and special core analyses, and further G&G studies.

Field Development Plan and Infrastructure Requirements

The issues outlined above must be addressed to reduce the large uncertainty currently associated with the discoveries before field development plans can be finalised and submitted for approval.

Kenya has limited oil infrastructure and no export facilities currently in place. The discoveries in Blocks 10BB and 13T are remote and cannot be delivered to market without significant infrastructure investment.

The Lokichar Basin is in a remote part of Kenya, approximately 850 km from the most likely point of export at Lamu. New build pipeline infrastructure and road upgrades will be required to permit field development and production export for these resources. Whilst there may be outline plans for this new infrastructure, there is currently no firm commitment or government approval.

Government Approval and Project Sanction

All of the Kenyan discoveries are located within Exploration Contracts; GCA understands that the Government of Kenya has extended these Exploration Contracts to allow further exploration and appraisal. Conversion of these permits to production permits has yet to be agreed.

Regulatory support and approval will be required for the commercialisation of the company's Kenyan Contingent Resources to proceed. In accordance with the Company's Production Sharing Contracts and joint venture agreements, field development plans must be agreed by the Company and its joint venture partners before submission for approval by the government.

Given the possible large scale of future development projects in Kenya to commercialise the Contingent Resources, significant capital requirements are anticipated which are potentially beyond the Company's current sources of capital. The Company may require financing from external sources, including issuance of new shares, issuance of debt or executing working interest farmout or disposition arrangements. There can be no assurance that such financing will be available to the Company or, if available, that it will be offered on terms acceptable to the Company.

Prior to project sanction for the areas in which the Company has an interest in Contingent Resources, numerous agreements and studies will need to be completed in addition to field development plans, including major engineering/procurement/construction agreements, environmental and social impact assessments, land acquisition agreements and community development plans.

BASIS OF OPINION

(EXTRACTED FROM THE GCA REPORT)

This document must be considered in its entirety. It reflects GCA's informed professional judgment based on accepted standards of professional investigation and, as applicable, the data and information provided by the Client and/or obtained from other sources e.g. public domain, the limited scope of engagement, and the time permitted to conduct the evaluation.

In line with those accepted standards, this document does not in any way constitute or make a guarantee or prediction of results, and no warranty is implied or expressed that actual outcome will conform to the outcomes presented herein. GCA has not independently verified any information provided by or at the direction of the Client and/or obtained from other sources e.g. public domain, and has accepted the accuracy and completeness of these data. GCA has no reason to believe that any material facts have been withheld from it, but does not warrant that its inquiries have revealed all of the matters that a more extensive examination might otherwise disclose.

The opinions expressed herein are subject to and fully qualified by the generally accepted uncertainties associated with the interpretation of geoscience and engineering data and do not reflect the totality of circumstances, scenarios and information that could potentially affect decisions made by the report's recipients and/or actual results. The opinions and statements contained in this report are made in good faith and in the belief that such opinions and statements are representative of prevailing physical and economic circumstances.

There are numerous uncertainties inherent in estimating reserves and resources, and in projecting future production, development expenditures, operating expenses and cash flows. Oil and gas reserve engineering and resource assessment must be recognized as a subjective process of estimating subsurface accumulations of oil and gas that cannot be measured in an exact way. Estimates of oil and gas reserves or resources prepared by other parties may differ, perhaps materially, from those contained within this report. The accuracy of any reserve estimate is a function of the quality of the available data and of engineering and geological interpretation. Results of drilling, testing and production that post-date the preparation of the estimates may justify revisions, some or all of which may be material. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered, and the timing and cost of those volumes that are recovered may vary from that assumed.

This assessment has been conducted within the context of GCA's understanding of the effects of petroleum legislation and other regulations that currently apply to these properties. However, GCA is not in a position to attest to property title or rights, conditions of these rights including environmental and abandonment obligations, and any necessary licenses and consents including planning permission, financial interest relationships or encumbrances thereon for any part of the appraised properties.

In carrying out this study, GCA is not aware that any conflict of interest has existed. As an independent consultancy, GCA is providing impartial technical, commercial and strategic advice within the energy sector. GCA's remuneration was not in any way contingent on the contents of this report. In the preparation of this document, GCA has maintained, and continues to maintain, a strict independent consultant-client relationship with the Client. Furthermore, the management and employees of GCA have no interest in any of the assets evaluated or related with the analysis carried out as part of this report.

Staff members who prepared this report are professionally qualified with appropriate educational qualifications and levels of experience and expertise to perform the work.

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